Monitoring of downhole parameters and tools utilizing fiber optics

ABSTRACT

The present invention provides systems utilizing fiber optics for monitoring downhole parameters and the operation and conditions of downhole tools. In one system fiber optics sensors are placed in the wellbore to make distributed measurements for determining the fluid parameters including temperature, pressure, fluid flow, fluid constituents and chemical properties. Optical spectrometric sensors are employed for monitoring chemical properties in the wellbore and at the surface for chemical injection systems. Fiber optic sensors are utilized to determine formation properties including resistivity and acoustic properties compensated for temperature effects. Fiber optic sensors are used to monitor the operation and condition of downhole devices including electrical submersible pumps and flow control devices. In one embodiment, a common fluid line is used to monitor downhole parameters and to operate hydraulically-operated devices. Fiber optic sensors are also deployed to monitor the physical condition of power lines supplying high electric power to downhole equipment. A light cell disposed downhole is used to generate electric power in the wellbore, which is used to charge batteries.

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority from Provisional U.S. PatentApplications Ser. Nos. 60/045,354 filed on May 2, 1997; 60/048,989 filedon Jun. 9, 1997; 60/052,042 filed on Jul. 9, 1997; 60/062,953 filed onOct. 10, 1997; 67/073425 filed on Feb. 2, 1998; and 60/079,446 filed onMar. 26, 1998. Reference is also made to a U.S. patent application filedon the same date as the present application under Attorney Docket No.414-12049 U.S., the contents of which are incorporated here byreference.

BACKGROUND OF THE INVENTION

[0002] 1. Field of the Invention

[0003] This invention relates generally to oilfield operations and moreparticularly to systems and methods utilizing fiber optics formonitoring wellbore parameters, formation parameters, drillingoperations, condition of downhole tools installed in the wellbores orused for drilling such wellbores, for monitoring reservoirs and formonitoring of remedial work.

[0004] 2. Background of the Art

[0005] A variety of techniques have been utilized for monitoringreservoir conditions, estimation and quantities of hydrocarbons (oil andgas) in earth formations, for determination formation and wellboreparameters and form determining the operating or physical condition ofdownhole tools.

[0006] Reservoir monitoring typically involves determining certaindownhole parameters in producing wellbores, such as temperature andpressure placed at various locations in the producing wellbore,frequently over extended time periods. Wireline tools are most commonlyutilized to obtain such measurements, which involves shutting down theproduction for extended time periods to determine pressure andtemperature gradients over time.

[0007] Seismic methods wherein a plurality of sensors are placed on theearth's surface and a source placed at the surface or downhole areutilized to obtain seismic data which is then used to update prior threedimensional (3-D″) seismic maps. Three dimensional maps updated overtime are sometimes referred to as “4-D” seismic maps. The 4-D mapsprovide useful information about reservoirs and subsurface structure.These seismic methods are very expensive. The wireline methods areutilized at great time intervals, thereby not providing continuousinformation about the wellbore conditions or that of the surroundingformations.

[0008] Permanent sensors, such as temperature sensors, pressure sensors,accelerometers or hydrophones have been placed in the wellbores toobtain continuous information for monitoring wellbores and thereservoir. Typically, a separate sensor is utilized for each type ofparameter to be determined. To obtain such measurements from usefulsegments of each wellbore, which may contain multilateral wellbores,requires using a large number of sensors, which require a large amountof power, data acquisition equipment and relatively large amount ofspace, which in many cases is impractical or cost prohibitive.

[0009] In production wells, chemicals are often injected downhole totreat the producing fluids. However, it can be difficult to monitor andcontrol such chemical injection in real time. Similarly, chemicals aretypically used at the surface to treat the produced hydrocarbons (i.e.break down emulsions) and to inhibit corrosion. However, it can bedifficult to monitor and control such treatment in real time.

[0010] Formation parameters are most commonly measured bymeasurement-while-drilling tools during the drilling of the wellboresand by wireline methods after the wellbores have been drilled. Theconventional formation evaluation sensors are complex and large in sizeand thus require large tools. Additionally such sensors are veryexpensive.

[0011] Prior art is also very deficient in providing suitable system andmethods for monitoring the condition or health of downhole tools. Toolconditions should be monitored during the drilling process, as the toolsare deployed in the wellbore and after deployment, whether during thecompletion phase or the production phase.

[0012] The present invention addresses some of the above-described priordeficiencies and provides systems and methods which utilize a variety offiber optic sensors for monitoring wellbore parameters, formationparameters, drilling operations, condition of downhole tools installedin the wellbores or used for drilling such wellbores, for monitoringreservoirs and for monitoring of remedial work. In some applications,the same sensor is configured to provide more than one measurement inmany instances these sensors are relatively, consume less power and canoperate at higher temperatures than the conventional sensors.

SUMMARY OF THE INVENTION

[0013] The present invention provides fiber optics based systems andmethods for monitoring downhole parameters and the condition andoperation of downhole tools. The sensors may be permanently disposeddownhole. The light source for the fiber optic sensors may be disposedin the wellbore or at the surface. The measurements from such sensorsmay be processed downhole and/or at the surface. Data may also be storedfor use for processing. Certain sensors may be configured to providemultiple measurements. The measurements made by the fiber optic sensorsin the present invention include temperature, pressure, flow, liquidlevel, displacement, vibration, rotation, acceleration, acousticvelocity, chemical species, acoustic field, electric field, radiation,pH, humidity, electrical field, magnetic field, corrosion and density.

[0014] In one system, a plurality of spaced apart fiber optic sensorsare disposed in the wellbore to take the desired measurements. The lightsource and the processor may be disposed in the wellbore or at thesurface. Two way communication between the sensors and the processor isprovided via fiber optic links or by conventional methods. A singlelight source may be utilized in the multilateral wellboreconfigurations. The sensors may be permanently installed in thewellbores during the completion or production phases. The sensorspreferably provide measurements of temperature, pressure and flow formonitoring the wellbore production and for performing reservoiranalysis.

[0015] In another system the fiber optic sensors are deployed in aproduction wellbore to monitor the injection operations, fracturing andfaults. Such sensors may also be utilized in the injection well.Controllers are provided to control the injection operation in responseto the in-situ or real time measurements.

[0016] In another system, the fiber optic sensors are used to determineacoustic properties of the formations including acoustic velocity andtravel time. These parameters are preferably compensated for the effectsof temperature utilizng the downhole temperature sensor measurements.Acoustic measurements are use for cross-well tomography and for updatingpreexisting seismic data or maps.

[0017] The distributed sensors of this invention find particular utilityin the monitoring and control of various chemicals which are injectedinto the well. Such chemicals are injected downhole to address a largenumber of known problems such as for scale inhibition and for thepretreatment of the fluid being produced. In accordance with the presentinvention, a chemical injection monitoring and control system includesthe placement of one or more sensors downhole in the producing zone formeasuring the chemical properties of the produced fluid as well as formeasuring other downhole parameters of interest. These sensors arepreferably fiber optic based and are formed from a sol gel matrix andprovide a high temperature, reliable and relatively inexpensiveindicator of the desired chemical parameter. The downhole chemicalsensors may be associated with a network of distributed fiber opticsensors positioned along the wellbore for measuring pressure,temperature and/or flow. Surface and/or downhole controllers receiveinput from the several downhole sensors, and in response thereto,control the injection of chemicals into the brothel.

[0018] The chemical parameters are preferably measured in real time andon-line and then used to control the amount and timing of the injectionof the chemicals into the wellbore or for controlling a surface chemicaltreatment system.

[0019] An optical spectrometer may be used downhole to determine theproperties of downhole fluid. The spectrometer includes a quartz probein contact with the fluid. Optical energy provided to the probe,preferably from a downhole source. The fluid properties such as thedensity, amount of oil, water, gas and solid contents affect therefraction of the light. The refracted light is analyzed to determinethe fluid properties. The spectrometer may be permanently installeddownhole.

[0020] The fiber optic sensors are also utilized to measure formationproperties, including resistivity, formation acoustic velocity. Othermeasurements may include electric field, radiation and magnetic field.Such measurements may be made with sensors installed or placed in thewellbore for monitoring the desired formation parameters. Such sensorsare also placed in the drill string, particularly in the bottom holeassembly to provide the desired measurements during the drilling of thewellbore.

[0021] In another system, the fiber optic sensors are used to monitorthe health or physical condition and/or the operation of the downholetools. The measurements made to monitor the tools include one or more of(a) vibration, (b) noise (c) strain (d) stress (e) displacement (f) flowrate (g) mechanical integrity (h) corrosion (i) erosion (j) scale (k)paraffin and (1) hydrate.

[0022] Examples of the more important features of the invention havebeen summarized rather broadly in order that the detailed descriptionthereof that follows may be better understood, and in order that thecontributions to the art maybe appreciated. There are, of course,additional features of the invention that will be described hereinafterand which will form the subject of the claims appended hereto.

BRIEF DESCRIPTION OF THE DRAWINGS

[0023] For a detailed understanding of the present invention, referenceshould be made to the following detailed description of the preferredembodiments, taken in conjunction with the accompanying drawings, inwhich like elements have been given like numerals, wherein:

[0024]FIG. 1 shows a schematic illustration of a multilateral wellboresystem and placement of fiber optic sensors according to one embodimentof the present invention.

[0025]FIG. 2 shows a schematic illustration of a configurations ofwellbores using fiber-optic sensor arrangements according to the presentinvention to: (a) to detect and monitor compressive stresses exerted onwellbore casings and formations; (b) determine the effectiveness of theinjection process and in-situ control of the injection operations, and(c) make acoustic measurements for cross-well tomography and to generateand/or update subsurface seismic maps.

[0026]FIG. 3 is a schematic illustrating both an injection well and aproduction well having sensors and flood front running between the wellsand loss through unintended fracturing.

[0027]FIG. 4 is a schematic representation wherein the production wellsare located on either side of the injection well.

[0028]FIG. 5 is a schematic illustration of a chemical injectionmonitoring and control system utilizing a distributed sensor arrangementand downhole chemical monitoring sensor system in accordance with oneembodiment of the present invention;

[0029]FIG. 6 is a schematic illustration of a fiber optic sensor systemfor monitoring chemical properties of produced fluids;

[0030]FIG. 7 is a schematic illustration of a fiber optic sol gelindicator probe for use with the sensor system of FIG. 6;

[0031]FIG. 8 is a schematic illustration of a surface treatment systemin accordance with the present invention; and

[0032]FIG. 9 is a schematic of a control and monitoring system for thesurface treatment system of FIG. 8.

[0033]FIG. 10 is a schematic illustration of a wellbore system wherein afluid conduit along a string placed in the wellbore is utilized foractivating a hydraulically-operated device and for monitoring downholeparameters using fiber optic sensors along its length.

[0034]FIG. 11 shows a schematic diagram of a producing well wherein afiber optic cable with sensors is utilized to determine the condition orhealth of downhole devices and to make measurements downhole relating tosuch devices and other downhole parameters.

[0035]FIG. 12 is a schematic illustration of a wellbore system whereinelectric power is generated downhole utilizing a light cell for use inoperating sensors and devices downhole.

[0036]FIG. 13 is a schematic illustration of a wellbore system wherein apermanently installed electrically-operated device is monitored andoperated by a fiber optic based system.

[0037]FIGS. 14A and 14B show a method to avoid drilling wellbores tooclose to or into each other from a common platform utilizing Fiber opticsensor in the drilling string.

[0038]FIG. 14C is schematic illustration of a bottomhole assembly foruse in drilling wellbores that utilizes with a number of fiber-opticsensors for measuring various downhole parameters during drilling of thewellbores.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

[0039]FIG. 1 shows an exemplary main or primary wellbore 12 formed fromthe surface 14 and lateral wellbores 16 and 18 formed from the mainwellbore 18. For the purpose of explanation, and not as any limitation,the main wellbore 12 is partly formed in a producing formation or payzone I and partly in a non-producing formation or dry formation II Thelateral wellbore 16 extends from the main wellbore 12 at a juncture 24into a second producing formation III. For the purposes of illustration,the wellbores herein are shown drilled from land, however, thisinvention is equally applicable to offshore wellbores. It should benoted that all wellbore configurations shown and described herein are toillustrate the concepts of present invention and shall not be construedto limit the inventions claimed herein.

[0040] In one application, a number of fiber optic sensors 40 are placein the wellbore 12. A single or a plurality of fiber optic sensors 40may be used so as to install the desired number of fiber optic sensors40 in the wellbore 12. As an example, FIG. 1 shows two serially coupledfiber optic segments 41 a and 41 b, each containing a plurality ofspaced apart fiber optic sensors 40. A light source and detector (LS) 46a coupled to an end 49 of the segment 41 a is disposed in the wellbore12 to transmit light energy to the sensors 40 and to receive thereflected light energy from the sensors 40. A data acquisition andprocessing unit (TDA) 48 a (also referred to herein as a “processor” or“controller”) may be disposed downhole to control the operation of thesensors 40, to process downhole sensor signals and data, and tocommunicate with other equipment and devices, including devices in thewellbores or at the surface (not shown).

[0041] Alternatively, a light source 46 b and/or the data acquisitionand processing unit 48 b may be place at the surface 14. Similarly,fiber optic sensor strings 45 may be disposed in other wellbores in thesystem, such as wellbores 16 and wellbore 18. A single light source,such as the light source 46 a or 46 b may be utilized for all fiberoptic sensors in the various wellbores, such as shown by dotted line 70.Alternatively, multiple light sources and data acquisition units may beused downhole, at the surface or in combination. Since the same sensormay make different types of measurements, the data acquisition unit 48 aor 48 is programmed to multiplex the measurement. Also different typesof sensors may be multiplexed as required. Multiplexing techniques areknow in the art and are thus not described in detail herein. The dataacquisition unit 46 a may be programmed to control the downhole sensors40 autonomously or upon receiving command signals from the surface or acombination of these methods.

[0042] The sensors 40 may be installed in the wellbores 12, 16, and 18before or after installing casings in wellbores, such as casing 52 showninstalled in the wellbore 12. This may be accomplished by connecting thestrings 41 a and 41 b along the inside of the casing 52. In one method,the strings 41 a and 41 b may be deployed or installed by roboticsdevices (not shown). The robotics device would move the sensor strings41 a and 41 b within the wellbore 12 to the desired location and installthem according to programmed instructions provided to the roboticsdevice. The robotics device may also be utilized to replace a sensor,conduct repairs retrieve the sensors or strings to the surface andmonitor the operation of downhole sensors or devices and gather data.Alternatively, the fiber optic sensors 40 maybe placed in the casing 52(inside, wrapped around, or in the casing wall) at the surface whileindividual casing sections (which are typically about forty-foot long)are joined prior to conveying the casing sections into the borehole.Stabbing techniques for joining casing or tubing sections are known inthe art and are preferred over rotational joints because stabbinggenerally provides better alignment of the end couplings 42 and alsobecause it allows operators to test and inspect optical connectionsbetween segments for proper two-way transmission of light energy throughthe entire string 41. For coiled tubing applications, the sensors may bewrapped on the outside or placed in conduit inside the tubing. Lightsources and data acquisition unit may also be placed in the coiledtubing prior to or after deployment.

[0043] Thus, in the system described in FIG. 1, a plurality of fiberoptic sensors 40 are installed spaced apart in one or more wellbores,such as wellbores 12, 16 and 18. If desired, each fiber optic sensor 40can be configured to operate in more than one mode to provide a numberof different measurements. The light source 46 a, and data detection andacquisition system 48 a may be placed downhole or at the surface.Although each fiber optic sensor 40 may provide measurements formultiple parameters, such sensors are still relatively small compared toindividual commonly used single measurement sensors, such as pressuresensors, stain gauges, temperature sensors, flow measurement devices andacoustic sensors. This enables making a large number of different typesof measurements utilizing relatively small downhole space. Installingdata acquisition and processing devices or units 48 a downhole allowsmaking a large number of data computations and processing downhole,avoiding the need of transmitting large amounts of data to the surfacestalling the light source 46 a downhole allows locating the source 46 aclose to the sensors 40, which avoids transmitting light to greatdistances from the surface thus avoiding loss of light energy. The datafrom the downhole acquisition system 48 a may be transmitted to thesurface by any suitable communication links or method including opticalfibers, wire connections, electromagnetic telemetry and acousticmethods. Data and signals may be transmitted downhole using the samecommunication links. Still in some applications, it may be desirable tolocate the light source 46 b and/or the data acquisition and processingsystem 48 b at the surface. Also, in some cases, it may be moreadvantageous to partially process data downhole and partially at thesurface.

[0044] In the present invention, the fiber optic sensors 40 may beconfigured to provide measurements for temperature, pressure, flow,liquid level displacement, vibration, rotation, acceleration, velocity,chemical species, radiation, pH, humidity, electric fields, acousticfields and magnetic fields.

[0045] Still referring to FIG. 1, any number of conventional sensors,generally denoted herein by numeral 60, may be disposed in any of thewellbores 12, 16 and 18. Such sensors may include sensors fordetermining resistivity of fluids and formations, gamma rays sensors andhydrophones. The measurements from the fiber optic sensors 40 andsensors 60 may be combined to determine the various conditions downhole.For example flow measurements from fiber optic sensors and theresistivity measurements from conventional sensors may be combined todetermine water saturation or to determine the oil, gas an watercontent. Alternatively, the fiber optic sensors may be utilized todetermine the same parameters.

[0046] In one mode, the fiber optic sensors are permanently installed inthe wellbores at selected locations. In a producing wellbore, thesensors continuously or periodically (as programmed) provide thepressure and/or temperature and/or fluid flow measurements. Suchmeasurements are preferably made for each producing zone in each of thewellbores. To perform certain types of reservoir analysis, it isrequired to know the temperature and pressure build rates in thewellbores. This requires measuring the temperature and pressure atselected locations downhole over extended time period after shuttingdown the well at the surface. In the prior art methods, the well is shutdown at the surface, a wireline tool is conveyed in to the wellbore andpositioned at one location in the wellbore. The tool continuouslymeasure temperature and pressure and may provide other measurements,such as flow control. These measurements are then utilized to performreservoir analysis, which may include determining the extent of thehydrocarbon reserves remaining in a field, flow characteristics of thefluid from the producing formations, water content, etc.

[0047] The above-described prior art methods do not provide continuousmeasurements while the well is producing and requires special wirelinetools that must be conveyed downhole. The present invention, on theother hand, provides in-situ measurements while the wellbore isproducing. The fluid flow information from each zone is used todetermine the effectiveness of each producing zone. Decreasing flowrates over time may indicate problems with the flow control devices,such as screens and sliding sleeves, or clogging of the perforations androck matrix near the wellbore. This information is used to determine thecourse of action, which may include further opening or closing slidingsleeves to increase or decrease the production rate, remedial work, suchas cleaning or reaming operations, shutting down a particular zone, etc.The temperature and pressure measurements are used to continuallymonitor each production zone and to update reservoir models. To makemeasurement for determining the temperature and pressure buildup rates,the wellbores are shut down and making of measurements continues. Thisdoes not require transporting wireline tools to the location, which canbe very expensive for offshore wellbores and wellbores drilled in remotelocations. Further, the in-situ measurements and computed data can becommunicated to a central office or to the offices of log and reservoirengineers via satellite. This continuous monitoring of wellbores allowstaking relatively quick action, which can significantly improve thehydrocarbon production from the wellbores. The above describedmeasurements may also be taken for non-producing zones, such as zone II,to aid in reservoir modeling, to determine the effect of production fromvarious wellbores on the field in which the wellbores are drilled.Optical spectrometers, as described later may be used to determine theconstituents of the formation fluid and certain chemical properties ofsuch fluids. Presence of gas may be detected to prevent blow-outs or totake other actions.

[0048]FIG. 2 shows a plurality of wellbores 102, 104 and 106 formed in afield 101 from the earth's surface 110. The wellbores in FIG. 2 areconfigured to describe the use of the fiber-optic sensor arrangementsaccording to the present invention to: (a) detect compressive stressesexerted into wellbore casings due to depletion of hydrocarbons or othergeological phenomena; (b) determine the effectiveness of injectionoperations and for in-situ monitoring and control of such operations,and (c) make acoustic measurements for cross-well tomography and togenerate and/or update subsurface seismic maps.

[0049] As an example only, and not as any limitation, FIG. 2 shows threewellbores 102, 104 and 106 formed in a common field or region ofinterest 101. For the purpose of illustration, the wellbores 102, 104and 106 are shown lined with respective casings 103, 105 and 107.Wellbore 102 contains a string 122 of fiber-optic sensors 40. Thesignals and data between the downhole sensor strings 122 and the surface110 are communicated via a two-way telemetry link 126. The casing 103may be made by coupling or joining tubulars or casing sections at thesurface prior to their insertion into the wellbore 102. The casingjoints are shown by numerals 120 a-n, which as indicated are typicallyabout forty (40) feet apart. Coiled tubing may also be used as thecasing.

[0050] The wellbore 102 has a production zone 130 from whichhydrocarbons are produced via perforations 132 made in the casing 103.The production zone 130 depletes as the fluid flows from the productionzone 130 into the wellbore 102. If the production rate is high, the rateof fluid depletion in the formations surrounding the production zone 130may be greater than the rate at which fluids can migrate into theformation to fill the depleted pores. The weight of the formation 138above the production zone exerts pressure 134 on the zone 130. If thepressure 134 is grater than what the rock matrix of the zone 130 cansupport, it starts to collapse, thereby exerting compressive stress onthe casing 103. If the compressive stress is excessive, the casing 103may break at one or more of the casing joints 102 a-n. In case of thecoiled tubing, it may buckle or collapse due to stresses. The stressescan also occur due to natural geological changes, such as shifting ofthe subsurface strata or due to deletion by other wells in the field101.

[0051] To detect compressive stresses in the casing 103, the fiber opticsensors 40 may be operated in the mode that provides strain gauge typeof measurements, which are then utilized to determine the extent of thecompressive stress on the casing 103. Since the sensor string 122 spansseveral joints, the system can be used to determine the location of thegreatest stress in the casing 103 and the stress distribution along anydesired section of the casing 103. This information may be obtainedperiodically or continuously during the life of the wellbore 102. Suchmonitoring of stresses provides early warning about the casing health orphysical condition and the condition of the zone 130. This informationallows the operator of the wellbore 102 to either decrease theproduction from the wellbore 102 or to shut down the well bore 102 andtake remedial measures to correct the problem.

[0052] The use of the fiber optic sensors to determine the effectivenessof remedial operations, such as fracturing or injection, will bedescribed while referring to wellbores 104 and 106 of FIG. 2. Wellbore104 is shown located at a distance “d₁ ” from the wellbore 102 and thewellbore 106 at a distance “d₂” from the wellbore 104. A string 124containing a number of spaced apart fiber-optic sensors 40 is disposedin the wellbore 104. The length of the string 124 and the number ofsensors 40 and their spacing depends upon the specific application. Thesignals and data between the string 124 and a surface equipment 151 arecommunicated over a two-way telemetry or communications link 128.

[0053] For the purpose of illustration and not as any limitation, thewellbore 106 will be utilized for injection purposes. The wellbore 106contains perforated zone 160. The wellbore is plugged by a packer or anyother suitable device 164 below the perforations to prevent fluid flowbeyond or downhole of the packer 164. To perform an injection operation,such as for fracturing the formation around the wellbore 106 or tostimulate the production from other wellbores in the field 101, such asthe wellbore 104, a suitable fluid 166 (such as steam) migrates towardthe wellbore 104 and may create a fluid wall 107 a. This causes thepressure across the wellbore 104 and fluid flow from the formation 180into the wellbore 104 may increase. Fracturing of the formation 180 intothe wellbore 104 may increase. Additionally, the fracturing of theformation 180 generates seismic waves, which generate acoustic energy.The fiber optic sensors 40 along with any other desired sensors disposedin the wellbore 104 measure the changes in the pressure, temperature,fluid flow, acoustic signals along the wellbore 104. The sensormeasurements (signals) are processed to determine the effectiveness ofthe injection operations. For example, the change in pressure, fluidflow at the wellbore 104 and the time and amount of injected materialcan be used to determine the effectiveness of the injection operations.Also, acoustic signals received at the wellbore provide usefulinformation about the extent of fracturing of the rock matrix offormation 180. Also, the acoustic signals received at the wellboreprovide useful information about the extent of fracturing of the rockmatrix for the formation 100. The acoustic signal analysis is used todetermine whether to increase or decrease the pressure of the injectedfluids 166 or to terminate the operation. This method enables theoperators to continuously monitor the effect of the injection operationin one wellbore, such as the wellbore 106, upon the other wellbores inthe field, such as wellbore 104.

[0054] The sensor configuration- shown in FIG. 2 may be utilized to mapsubsurface formations. In one method, an acoustic source (AS) 170, suchas a vibrator or an explosive charge, is activated at the surface 110.The sensors 40 in the wellbores 102 and 104 detect acoustic signalswhich travel from the source 170 to the sensors 40 through the formation180. These signals are processed by any of the methods known in the artto map the subsurface formations and/or update the existing maps, whichare typically obtained prior to drilling wellbores, such as wellbores102 and 104. Two dimensional or three dimensional seismic maps arecommonly obtained before drilling wellbores. The data obtained by theabove-described method is used to update such maps. Updating threedimensional or 3D maps over time provides what are referred to in theoil and gas industry as four dimensional or “4D” maps. These maps arethen used to determine the conditions of the reservoirs, to performreservoir modeling and to update existing reservoir models. Thesereservoir models are used to manage the oil and gas production from thevarious wellbores in the field. The acoustic data obtained above is alsoutilized for cross-well tomography. Also, the acoustic source 170 may bedisposed (activated) within one or more of the wellbores, such as shownby numeral 170 in wellbore 104. The acoustic source is moved to otherlocations, such as shown by dotted box 170 to take additionalmeasurements. The fiber optic sensors described herein may bepermanently deployed in the wellbores.

[0055] In another embodiment of the invention relating to fracturing,illustrated schematically in FIG. 3, downhole sensors measure straininduced in the formation by the injected fluid. Strain is an importantparameter for avoiding exceeding the formation parting pressure orfracture pressure of the formation with the injected fluid. By avoidingthe opening of or widening of natural pre-existing fractures largeunswept areas of the reservoir can be avoided. The reason thisinformation is important in the regulation of pressure of the fluid toavoid such activity is that when pressure opens fractures or newfractures are created there is a path of much less resistance for thefluid to run through. Since the injection fluid will follow along thepath of least resistance it would generally run in the fractures andaround areas of the reservoir that need to be swept. This substantiallyreduces its efficiency. The situation is generally referred to in theart as an “artificially high permeability channel.” Another detriment tosuch a condition is the uncontrolled loss of injected fluids. Thisresults in loss of oil due to the reduced efficiency of the sweep andadditionally may function as an economic drain due to the loss ofexpensive fluids.

[0056]FIG. 3 schematically illustrates the embodiment and the conditionset forth above by illustrating an injection well 250 and a productionwell 260. Fluid 252 is illustrated escaping via the unintended fracturefrom the formation 254 into the overlying gas cap level 256 and theunderlying water table 261. The condition is avoided by the invention byusing pressure sensors to limit the injection fluid pressure asdescribed above. The rest of the fluid 252 is progressing as it isintended to through the formation 254. In order to easily and reliablydetermine what the stress is in the formation 54, fiber optic acousticsensors 256 are located in the injection well 250 at various pointstherein. The acoustic sensors 256 pick up sounds generated by stress inthe formation which propagate through the reservoir fluids or reservoirmatrix to the injection well. In general, higher sound levels wouldindicate severe stress in the formation and should generate a reductionin pressure of the injected fluid whether by automatic control or bytechnician control. A data acquisition system 258 is preferable torender the system extremely reliable and system 258 may be at thesurface where it is illustrated in the schematic drawing or may bedownhole. Based upon acoustic signals received the system of theinvention, preferably automatically, although manually is workable,reduces pressure of the injected fluid by reducing pump pressure.Maximum sweep efficiency is thus obtained.

[0057] In yet another embodiment of the invention, as schematicallyillustrated in FIG. 4, acoustic generators and receivers are employed todetermine whether a formation which is bifurcated by a fault is sealedalong the fault or is permeable along the fault. It is known by one ofordinary skill in the art that different strata within a formationbifurcated by a fault may have some zones that flow and some zones thatare sealed; this is the illustration of FIG. 4. Referring directly toFIG. 4, injection well 270 employs a plurality of fiber optic sensors272 and acoustic generators 274 which, most preferably, alternate withincreasing depth in the wellbore. In production well 280, a similararrangement of sensors 272 and acoustic generators 274 are positioned.The sensors and generators are preferably connected to processors whichare either downhole or on the surface and preferably also connect to theassociated production or injection well. The sensors 272 can receiveacoustic signals that are naturally generated in the formation,generated by virtue of the fluid flowing through the formation from theinjection well and to the production well and also can receive signalswhich are generated by signal generators 274. Where signal generators274 generate signals, the reflected signals that are received by sensors272 over a period of time can indicate the distance and acoustic volumethrough which the acoustic signals have traveled. This is illustrated inarea A of FIG. 4 in that the fault line 275 is sealed between area A andarea B on the figure. This is illustrated for purposes of clarity onlyby providing circles 276 along fault line 275. The areas of fault line275 which are permeable are indicated by hash marks 277 through faultline 275. Since the acoustic signal represented by arrows andsemi-curves and indicated by numeral 278 cannot propagate through thearea C which bifurcates area A from area B on the left side of thedrawing, that signal will bounce and it then can be picked up by sensor272. The time delay, number and intensity of reflections andmathematical interpretation which is common in the art provides anindication of the lack of pressure transmissivity between those twozones. Additionally this pressure transmissivity can be confirmed by thedetection by said acoustic signals by sensors 272 in the production well280. In the drawing, the area directly beneath area A, indicated as areaE, is permeable to area B through fault 275 because the region D in thatarea is permeable and will allow flow of the flood front from theinjection well 270 through fault line 275 to the production well 280.Acoustic sensors and generators can be employed here as well since theacoustic signal will travel through the area D and, therefore,reflection intensity to the receivers 272 will decrease. Time delay willincrease. Since the sensors and generators are connected to a centralprocessing unit and to one another it is a simple operation to determinethat the signal, in fact, traveled from one well to the other andindicates permeability throughout a particular zone. By processing theinformation that the acoustic generators and sensors can provide theinjection and production wells can run automatically by determiningwhere fluids can flow and thus opening and closing valves at relevantlocations on the injection well and production well in order to flushproduction fluid in a direction advantageous to run through a zone ofpermeability along the fault.

[0058] Other information can also be generated by this alternate systemof the invention since the sensors 272 are clearly capable of receivingnot only the generated acoustic signals but naturally occurring acousticwaveforms arising from both the flow of the injected fluids as theinjection well and from those arising within the reservoirs in result ofboth fluid injection operations and simultaneous drainage of thereservoir in resulting production operations. The preferred permanentdeployment status of the sensors and generators of the invention permitand see to the measurements simultaneously with ongoing injectionflooding and production operations. Advancements in both acousticmeasurement capabilities and signal processing while operating theflooding of the reservoir represents a significant, technologicaladvance in that the prior art requires cessation of theinjection/production operations in order to monitor acoustic parametersdownhole. As one of ordinary skill in the art will recognize thecessation of injection results in natural redistribution of the activeflood profile due primarily to gravity segregation of fluids andentropic phenomena that are not present during active floodingoperations. This also enhances the possibility of prematurebreakthrough, as oil migrates to the relative top of the formation andthe injected fluid, usually water, migrates to the relative bottom ofthe formation. Hence, there is a significant possibility that the waterwill actually reach the production well and thus further pumping ofsteam or water will merely run underneath the layer of oil at the top ofthe formation and the sweep of that region would be extremely difficultthereafter.

[0059] In yet another embodiment of the invention fiber optics areemployed (similar to those disclosed in the U.S. application filed onJun. 10, 1997 entitled CHEMICAL INJECTION WELL CONTROL AND MONITORINGSYSTEM under Attorney docket number 97-1554 and BEH 197-09539-U.S. whichis fully incorporated herein by reference) to determine the amount ofand/or presence of biofouling within the reservoir by providing aculture chamber within the injection or production well, wherein lightof a predetermined wavelength may be injected by a fiber optical cable,irradiating a sample determining the degree to which biofouling may haveoccurred. As one of ordinary skill in the art will recognize, variousbiofouling organisms will have the ability to fluoresce at a givenwavelength, that wavelength once determined, is useful for the purposeabove stated.

[0060] Referring back to FIG. 2, the flood front may also be monitoredfrom the “back” employing sensors 155 installed in the injection well106. These sensors provide acoustic signals which reflect from thewater/oil interface thus providing an accurate picture in a moment intime of the three-dimensional flood front. Taking real time 4D picturesprovides an accurate format of the density profile of the formation dueto the advancing flood front. Thus, a particular profile and therelative advancement of the front can be accurately determined by thedensity profile changes. It is certainly possible to limit the sensorsand acoustic generators to the injection well for such a system.However, it is generally more preferable to also introduce sensors andacoustic generators in the production well toward which the front ismoving (as described before) thus allowing an immediate double check ofthe fluid front profile. That is, acoustic generators on the productionwell will reflect a signal off the oil/water interface and will providean equally accurate three-dimensional fluid front indicator. Theindicators from both sides of the front should agree and thus providesan extremely reliable indication of location and profile. A commonprocessor 151 may be used for processing data from the wells 102-106.

[0061] Referring now to FIG. 5, the distributed fiber optic sensors ofthe type described above are also well suited for use in a productionwell where chemicals are being injected therein and there is a resultantneed for the monitoring of such a chemical injection process so as tooptimize the use and effect of the injected chemicals. Chemicals oftenneed to be pumped down a production well for inhibiting scale, paraffinsand the like as well as for other known processing applications andpretreatment of the fluids being produced. Often, as shown in FIG. 5,chemicals are introduced in an annulus 400 between the production tubing402 and the casing 404 of a well 406. The chemical injection (shownschematically at 408) can be accomplished in a variety of known methodssuch as in connection with a submersible pump (as shown for example inU.S. Pat. No. 4,582,131, assigned to the assignee hereof andincorporated herein by reference) or through an auxiliary lineassociated with a cable used with an electrical submersible pump (suchas shown for example in U.S. Pat. No. 5,528,824, assigned to theassignee hereof and incorporated herein by reference).

[0062] In accordance with an embodiment of the present invention, one ormore bottomhole sensors 410 are located in the producing zone 405 forsensing a variety of parameters associated with the producing fluidand/or interaction of the injected chemical and the producing fluid 407.Thus, the bottom hole sensors 410 will sense parameters relative to thechemical properties of the produced fluid such as the potential ioniccontent, the covalent content, pH level, oxygen levels, organicprecipitates and like measurements. Sensors 410 can also measurephysical properties associated with the producing fluid and/or theinteraction of the injected chemicals and producing fluid such as theoil/water cut, viscosity and percent solids. Sensors 410 can alsoprovide information related to paraffin and scale build-up, H₂S contentand the like.

[0063] Bottomhole sensors 410 preferably communicate with and/or areassociated with a plurality of distributed sensors 412 which arepositioned along at least a portion of the wellbore (e.g., preferablythe interior of the production tubing) for measuring pressure,temperature and/or flow rate as discussed above in connection withFIG. 1. The present invention is also preferably associated with asurface control and monitoring system 414 and one or more known surfacesensors 415 for sensing parameters related to the produced fluid; andmore particularly for sensing and monitoring the effectiveness oftreatment rendered by the injected chemicals. The sensors 415 associatedwith surface system 414 can sense parameters related to the content andamount of, for example, hydrogen sulfide, hydrates, paraffins, water,solids and gas.

[0064] Preferably, the production well disclosed in FIG. 5 hasassociated therewith a so-called “intelligent” downhole control andmonitoring system which may include a downhole computerized controller418 and/or the aforementioned surface control and monitoring system 414.This control and monitoring system is of the type disclosed in U.S. Pat.No. 5,597,042, which is assigned to the assignee hereof and fullyincorporated herein by reference. As disclosed in U.S. Pat. No.5,597,042, the sensors in the “intelligent” production wells of thistype are associated with downhole computer and/or surface controllerswhich receive information from the sensors and based on thisinformation, initiate some type of control for enhancing or optimizingthe efficiency of production of the well or in some other way effectingthe production of fluids from the formation. In the present invention,the surface and/or downhole computers 414, 418 will monitor theeffectiveness of the treatment of the injected chemicals and based onthe sensed information, the control computer will initiate some changein the manner, amount or type of chemical being injected. In the systemof the present invention, the sensors 410 and 412 may be connectedremotely or in-situ.

[0065] In a preferred embodiment of the present invention, thebottomhole sensors comprise fiber optic chemical sensors. Such fiberoptic chemical sensors preferably utilize fiber optic probes which areused as a sample interface to allow light from the fiber optic tointeract with the liquid or gas stream and return to a spectrometer formeasurement. The probes are typically composed of sol gel indicators.Sol gel indicators allow for on-line, real time measurement and controlthrough the use of indicator materials trapped in a porous, sol gelderived, glass matrix. Thin films of this material are coated ontooptical components of various probe designs to create sensors forprocess and environmental measurements. These probes provide increasedsensitivity to chemical species based upon characteristics of thespecific indicator. For example, sol gel probes can measure with greataccuracy the pH of a material and sol gel probes can also measure forspecific chemical content. The sol gel matrix is porous, and the size ofthe pores is determined by how the glass is prepared. The sol gelprocess can be controlled so as to create a sol gel indicator compositewith pores small enough to trap an indicator in the matrix but largeenough to allow ions of a particular chemical of interest to pass freelyin and out and react with the indicator. An example of suitable sol gelindicator for use in the present invention is shown in FIGS. 6 and 7.

[0066] Referring to FIGS. 6 and 7, a probe is shown at 416 connected toa fiber optic cable 418 which is in turn connected both to a lightsource 420 and a spectrometer 422. As shown in FIG. 7, probe 416includes a sensor housing 424 connected to a lens 426. Lens 426 has asol gel coating 428 thereon which is tailored to measure a specificdownhole parameter such as pH or is selected to detect the presence,absence or amount of a particular chemical such as oxygen, H₂S or thelike. Attached to and spaced from lens 426 is a mirror 430. During use,light from the fiber optic cable 418 is collimated by lens 426 whereuponthe light passes through the sol gel coating 428 and sample space 432.The light is then reflected by mirror 430 and returned to the fiberoptical cable. Light transmitted by the fiber optic cable is measured bythe spectrometer 422. Spectrometer 422 (as well as light source 420) maybe located either at the surface or at some location downhole. Based onthe spectrometer measurements, a control computer 414, 416 will analyzethe measurement and based on this analysis, the chemical injectionapparatus 408 will change the amount (dosage and concentration), rate ortype of chemical being injected downhole into the well. Information fromthe chemical injection apparatus relating to amount of chemical left instorage, chemical quality level and the like will also be sent to thecontrol computers. The control computer may also base its controldecision on input received from surface sensor 415 relating to theeffectiveness of the chemical treatment on the produced fluid, thepresence and concentration of any impurities or undesired by-productsand the like.

[0067] Alternatively a spectrometer may be utilized to monitor certainproperties of downhole fluids. The sensor includes a glass or quartzprobe, one end or tip of which is placed in contact with the fluid.Light supplied to the probe is refracted based on the properties of thefluid. Spectrum analysis of the refracted light is used to determine theand monitor the properties, which include the water, gas, oil and solidcontents and the density.

[0068] In addition to the bottomhole sensors 410 being comprised of thefiber optic sol gel type sensors, distributed sensors 412 alongproduction tubing 402 may also include the fiber optic chemical sensorsof the type discussed above. In this way, the chemical content of theproduction fluid may be monitored as it travels up the production tubingif that is desirable.

[0069] The permanent placement of the sensors 410, 412 and controlsystem 417 downhole in the well leads to a significant advance in thefield and allows for real time, remote control of chemical injectionsinto a well without the need for wireline device or other wellinterventions.

[0070] In accordance with the present invention, a novel control andmonitoring system is provided for use in connection with a treatingsystem for handling produced hydrocarbons in an oilfield. Referring toFIG. 8, a typical surface treatment system used for treating producedfluid in oil fields is shown. As is well known, the fluid produced fromthe well includes a combination of emulsion, oil, gas and water. Afterthese well fluids are produced to the surface, they are contained in apipeline known as a “flow line.” The flow line can range in length froma few feet to several thousand feet. Typically, the flow line isconnected directly into a series of tanks and treatment devices whichare intended to provide separation of the water in emulsion from the oiland gas. In addition, it is intended that the oil and gas be separatedfor transport to the refinery.

[0071] The produced fluids flowing in the flow line and the variousseparation techniques which act on these produced fluids lead to seriouscorrosion problems. Presently, measurement of the rate of corrosion onthe various metal components of the treatment systems such as the pipingand tanks is accomplished by a number of sensor techniques includingweight loss coupons, electrical resistance probes,electrochemical—linear polarization techniques, electrochemical noisetechniques and AC impedance techniques. While these sensors are usefulin measuring the corrosion rate of a metal vessel or pipework, thesesensors do not provide any information relative to the chemicalsthemselves, that is the concentration, characterization or otherparameters of chemicals introduced into the treatment system. Thesechemicals are introduced for a variety of reasons including corrosioninhibition and emulsion breakdown, as well as scale, wax, asphaltene,bacteria and hydrate control.

[0072] In accordance with an important feature of the present invention,sensors are used in chemical treatment systems of the type disclosed inFIG. 8 which monitors the chemicals themselves as opposed to the effectsof the chemicals (for example, the rate of corrosion). Such sensorsprovide the operator of the treatment system with a real timeunderstanding of the amount of chemical being introduced, the transportof that chemical throughout the system, the concentration of thechemical in the system and like parameters. Examples of suitable sensorswhich may be used to detect parameters relating to the chemicals in thetreatment system include the fiber optic sensor described above withreference to FIGS. 6 and 7. Ultrasonic absorption and reflection,laser-heated cavity spectroscopy (LIMS), X-ray fluorescencespectroscopy, neutron activation spectroscopy, pressure measurement,microwave or millimeter wave radar reflectance or absorption, and otheroptical and acoustic (i.e., ultrasonic or sonar) methods may also beused. A suitable microwave sensor for sensing moisture and otherconstituents in the solid and liquid phase influent and effluent streamsis described in U.S. Pat. No. 5,455,516, all of the contents of whichare incorporated herein by reference. An example of a suitable apparatusfor sensing using LIBS is disclosed in U.S. Pat. No. 5,379,103 all ofthe contents of which are incorporated herein by reference. An exampleof a suitable apparatus for sensing LIMS is the LASMA Laser MassAnalyzer available from Advanced Power Technologies, Inc. of Washington,D.C. An example of a suitable ultrasonic sensor is disclosed in U.S.Pat. No. 5,148,700 (all of the contents of which are incorporated hereinby reference). A suitable commercially available acoustic sensor is soldby Entech Design, Inc., of Denton, Tex. under the trademark MAPS®.Preferably, the sensor is operated at a multiplicity of frequencies andsignal strengths. Suitable millimeter wave radar techniques used inconjunction with the present invention are described in chapter 15 ofPrinciples and Applications of Millimeter Wave Radar, edited by N. C.Currie and C. E. Brown, Artech House, Norwood, Mass. 1987.

[0073] While the sensors may be utilized in a system such as shown inFIG. 8 at a variety of locations, the arrows numbered 500, through 516indicate those positions where information relative to the chemicalintroduction would be especially useful.

[0074] Referring now to FIG. 9, the surface treatment system of FIG. 8is shown generally at 520. In accordance with the present invention, thechemical sensors (i.e. 500-516) will sense, in real time, parameters(i.e., concentration and classification) related to the introducedchemicals and supply that sensed information to a controller 522(preferably a computer or microprocessor based controller). Based onthat sensed information monitored by controller 522, the controller willinstruct a pump or other metering device 524 to maintain, vary orotherwise alter the amount of chemical and/or type of chemical beingadded to the surface treatment system 520. The supplied chemical fromtanks 526 can, of course, comprise any suitable treatment chemical suchas those chemicals used to treat corrosion, break down emulsions, etc.Examples of suitable corrosion inhibitors include long chain amines oraminodiazolines. Suitable commercially available chemicals includeCronoxÔ which is a corrosion inhibitor sold by Baker Petrolite, adivision of Baker-Hughes Incorporated, of Houston, Tex.

[0075] Thus, in accordance with the control and monitoring system ofFIG. 9, based on information provided by the chemical sensors 500-516,corrective measures can be taken for varying the injection of thechemical (corrosion inhibitor, emulsion breakers, etc.) into the system.The injection point of these chemicals could be anywhere upstream of thelocation being sensed such as the location where the corrosion is beingsensed. Of course, this injection point could include injectionsdownhole. In the context of a corrosion inhibitor, the inhibitors workby forming a protective film on the metal and thereby prevent water andcorrosive gases from corroding the metal surface. Other surfacetreatment chemicals include emulsion breakers which break the emulsionand facilitate water removal. In addition to removing or breakingemulsions, chemicals are also introduced to break out and/or removesolids, wax, etc. Typically, chemicals are introduced so as to providewhat is known as a base sediment and water (B.S. and W) of less than 1%.

[0076] In addition to the parameters relating to the chemicalintroduction being sensed by chemical sensors 500-516, the monitoringand control system of the present invention can also utilize knowncorrosion measurement devices as well including flow rate, temperatureand pressure sensors. These other sensors are schematically shown inFIG. 9 at 528 and 530. The present invention thus provides a means formeasuring parameters related to the introduction of chemicals into thesystem in real time and on line. As mentioned, these parameters includechemical concentrations and may also include such chemical properties aspotential ionic content, the covalent content, pH level, oxygen levels,organic precipitates and like measurements. Similarly, oil/water cutviscosity and percent solids can be measured as well as paraffin andscale build-up, H₂S content and the like. The fiber optic sensorsdescribed above may be used to determine the above mentioned parameterdownhole.

[0077]FIG. 10 is a schematic diagram of a wellbore system 600 wherein acommon conduit is utilized for operating a downholehydraulically-operated tool or device and for monitoring one or moredownhole parameters utilizing the fiber optics. System 600 includes awellbore 602 having a surface casing 601 installed a short distance fromthe surface 604. After the wellbore 102 has been drilled to a desireddepth. A completion or production string 606 is conveyed into thewellbore 602. The string 606 includes at least one downholehydraulically-operated device 614 carried by a tubing 608 which tubingmay be a drill pipe, coiled tubing or production tubing. A fluid conduit610 (or hydraulic line) having a desired inner diameter 611 is placed orattached either on the outside of the string 606 (as shown in FIG. 10)or in the inside of the string in any suitable manner. The conduit 610is preferably routed at a desired location on the string 606 via au-joint 612 so as to provide a smooth transition for returning theconduit 610 to the surface 604. A hydraulic connection 624 is providedfrom the-conduit 610 to the device 614 so that a fluid under pressurecan pass from the conduit 610 to the device 614.

[0078] After the string 606 has been placed or installed at a desireddepth in the wellbore 602, an optical fiber 612 is pumped under pressureat the inlet 630 a from a source of fluid 630. The optical fiber 622passes through the entire length of the conduit 610 and returns to thesurface 604 via outlet 630 b. The fiber 622 is then optically coupled toa light source and recorder (or detector) (LS/REC) 640. A dataacquisition/signal processor (DA/SP) 642 processes data/signal receivedvia the optical fiber 622 and also controls the operation of the lightsource and recorder 640.

[0079] The optical fiber 622 may include a plurality of sensors 620distributed along its length. Sensors 620 may include temperaturesensors, pressure sensors, vibration sensors or any other fiber opticsensor that can be placed on the fiber optic cable 622. Sensors 620 areformed into the cable 622 during the manufacturing of the cable 622. Thedownhole device 614 may be any downhole fluid-activated device includingbut not limited to a valve, a choke, a sliding sleeve, a perforatingdevice, and a packer, fluid flow regulation device, or any othercompletion and/or production device. The device 614 is activated bysupplying fluid under pressure through the conduit 610. In theembodiment shown herein, the line 610 receives fiber optic cable 622throughout its length and is connected to surface instrumentation 640and 642 for distributed measurements of downhole parameters along itslength. The line 610 may be arranged downhole along the string 606 in aV or other convenient shape. Alternatively, the line 610 may terminateat the device 614 and/or continue to a second device (not shown)downhole. the fiber optic sensors also may be disposed on the line inany other suitable manner such as wrapping them on the outside of theconduit 610. In the present invention, a common line is thus used tocontrol a hydraulically-controlled device and to monitor one or moredownhole parameters along the line.

[0080] During the completion of the wellbore 602, the sensors 620provide useful measurements relating to their associated downholeparameters and the line 606 is used to actuate a downhole device. Thesensors 620 continue to provide information about the downholeparameters over time.

[0081]FIG. 11 shows a schematic diagram of a producing well 702 thatpreferably has two electric submersible pumps (“ESP”) 714, one forpumping the oil/gas 706 to the surface 703 and the other to pump anyseparated water back into a formation. The formation fluid 706 flowsfrom a producing zone 708 into the wellbore 702 via perforations 707.Packers 710 a and 710 b installed below and above the ESP 714 force thefluid 706 to flow to the surface 703 via pumps ESP 714. An oil waterseparator 750 separates the oil and water and provide them to theirrespective pumps 714 a-714 b. A choke 752 provides desired backpressure. An instrument package 760 and pressure sensor is installed inthe pump string 718 to measure related parameters during production. Thepresent invention utilizes optical fiber with embedded sensors toprovide measurements of selected parameters, such as temperature,pressure, vibration, flow rate as described below. ESP's 714 use largeamounts of electric power which is supplied from the surface via a powercable 724. Such cables often tend to corrode an/or overheated. Due tothe high power being carried by the cable 724, electrical sensors aregenerally not placed on or along side the cable 724.

[0082] In one embodiment of the present invention as shown in FIG. 11, afiber optic cable 722 carrying sensors 720 is placed along the powercable 724. The fiber optic cable 702 may also be extended below theESP's 714 to replace conventional sensors in the instrumentation package760 and to provide control signals to the downhole device or processorsas described earlier. E1 one application, the sensors 720 measurevibration and temperature of the ESP 714. It is desirable to operate theESP at a low temperature and without excessive vibration. The ESP 714speed is adjusted so as to maintain one or both such parameters belowtheir predetermined maximum value or within their respectivepredetermined ranges. The fiber optic sensors are used in thisapplication to continuously or periodically determine the physicalcondition (health) of the ESP The fiber optic cable 722 may be extendedor deployed below the ESP at the time of installing the productionstring 718 in the manner described with respect to FIG. 10. It should beobvious that the use of the ESP is only one example of the downholedevice that can be used for the purposes of this invention. The presentinvention may be used to continuously measure downhole parameters, tomonitor the health or condition of downhole devices and to controldownhole devices. Any suitable device may be utilized for this purposeincluding, sliding sleeves, packers, flow control devices etc.

[0083]FIG. 12 shows a wellbore 802 with a production string 804 havingone or more electrically-operated or optically-operated devices,generally denoted herein by numeral 850 and one or more downhole sensors814. The string 804 includes batteries 812 which provide electricalpower to the devices 850 and sensors 814. The batteries are charged bygenerating power downhole by turbines (not shown) or by supplying powerfrom the surface via a cable (not shown).

[0084] In the present invention a light cell 810 is provided in thestring 804 which is coupled to an optical fiber 822 that has one or moresensors 820 associated therewith. A light source 840 at the surfaceprovides light to the light cell 810 which generates electricity whichcharges the downhole batteries 812. The light cell 810 essentiallytrickle charges the batteries. In many applications the downholedevices, such as devices 850, are activated infrequently. Tricklecharging the batteries may be sufficient and thus may eliminate the useof other power generation devices. In applications requiring greaterpower consumption, the light cell may be used in conjunction with otherconventional power generation devices.

[0085] Alternatively, if the device 850 is optically-activated, thefiber 822 is coupled to the device 850 as shown by the dotted line 822 aand is activated by supplying optical pulses from the surface unit 810.Thus, in the configuration of FIG. 12, a fiber optics device is utilizedto generate electrical energy downhole, which is then used to charge asource, such as a battery, or operate a device. The fiber 822 is alsoused to provide two-way communication between the DA/SP 842 and downholesensors and devices.

[0086]FIG. 13 shows a schematic of a wellbore system 900 wherein apermanently installed electrically-operated device is monitored andcontrolled by a fiber optic based system. The system 900 includes awellbore 902 and an electrically-operated device 904 installed at adesired depth, which may be a sliding sleeve, a choke, a fluid flowcontrol device, etc. An control unit 906 controls the operation of thedevice 904. A production tubing 910 installed above the device 904allows formation fluid to flow to the surface 901. During themanufacture of the string 911 that includes the device 904 and thetubing 910, a conduit 922 is clamped along the length of the tubing 910with clamps 921. An optical coupler 907 is provided at the electricalcontrol unit 906 which can mate with a coupler fed through the conduit922.

[0087] Either prior to or after placing the string 910 in the wellbore902, a fiber optic cable 921 is deployed in the conduit 922 so that acoupler 922 a at the cable 921 end would couple with the coupler 907 ofthe control unit 906. A light source 990 provides the light energy tothe fiber 922. A plurality of sensors 920 may be deployed along thefiber 922 as described before. A sensor preferably provided on the fiber922 determines the flow rate of formation fluid 914 flowing through thedevice 904. Command signals are sent by DA/SP 942 to activate the device904 via the fiber 922. These signals are detected by the control unit906, which in turn operate the device 904. This, in the configuration ofFIG. 13, fiber optics is used to provide two way communication betweendownhole devices, sensors and a surface unit and to operate the downholedevices.

[0088]FIGS. 14A and 14B show a method monitoring the location of priorwells during drilling of a wellbore so as to avoid drilling the wellboretoo close to or into the existing wellbores. Several wellbores aresometimes drilled from a rig at a single location. This is a commonpractice in offshore drilling because moving large platforms or rigs isnot practical. Often, thirty to forty wellbores are drilled from asingle location. A template is used to define the relative location ofthe wells at the surface. FIGS. 14A and 14B show wellbores 1004-1008drilled from a common template 1005. The template 1005 shows openings1004 a, 1006 a, and 1008 a as surface locations for the wellbores 1004,1006 and 1008 respectively. Locations of all other wellbores drilledfrom the template 1005 are referred to by numeral 1030. FIG. 14B alsoshows a lateral or branch wellbore 1010 being drilled from the wellbore1004, by a drill bit 1040. The wellbore 1008 is presumed to be drilledbefore wellbores 1004 and 1010. For the purposes of this example, it isassumed that the driller wishes to avoid drilling the wellbore 1010 tooclose to or onto the wellbore 1008. Prior to drilling the wellbore 1010,a plurality of fiber optic sensors 40 are disposed in the wellbore 1008.The vibrations of the drill bit 1040 during drilling of the wellbore1010 generate acoustic energy, which travels to the wellbore 1008 by aprocessor of the kind described earlier. The sensors 40 in the well bore1008 detect acoustic signals received at the well bore 1008. Thereceived signals are processed and analyzed to determine the distance ofthe drill bit from the wellbore 1008. The travel time of the acousticsignals from the drill bit 1040 to the sensors 40 in the wellbore 1008provides relatively accurate measure of such distance. The fiber optictemperature sensor measurements are preferably used to correct orcompensate the travel time or the underlying velocity for the effects oftemperature. The driller can utilize this information to ensure that thewellbore 1010 is being drilled at a safe distance from the wellbore1008, thereby avoiding drilling it too close or into the wellbore 1008.

[0089] The fiber optic sensors described above are especially suitablefor use in drill strings utilized for drilling wellbores. For thepurposes of this invention, a “drill string” includes a drillingassembly or bottom hole assembly (“BHA”) carried by a tubing which maybe drill pipe or coiled tubing. A drill bit is attached to the BHA whichis rotated by rotating the drill pipe or by a mud motor. FIG. 14C showsa bottomhole assembly 1080 having the drill bit 1040 at one end. Thebottomhole assembly 1080 is conveyed by a tubing 1062 such as a drillpipe or a coiled-tubing. A mud motor 1052 drives the drill bit 1040attached to the bottom hole end of the BHA. A bearing assembly 1055coupled to the drill bit 1040 provides lateral and axial support to thedrill bit 1040. Drilling fluid 1060 passes through the drilling assembly1080 and drives the mud motor 1052, which in turn rotates the drill bit1040.

[0090] As described below, a variety of fiber optic sensors are placedin the BHA 1080, drill bit 1040 and the tubing 1082. Temperature andpressure sensors T4 and P5 are placed in the drill bit for monitoringthe condition of the drill bit 1040. Vibration and displacement sensorsV1 monitor the vibration of the BHA and displacement sensors V1 monitorthe lateral and axial displacement of the drill shaft and that of theBHA. Sensors T1-T3 monitor the temperature of the elastomeric stator ofthe mud motor 1052, while the sensors P1-P4 monitor differentialpressure across the mud motor, pressure of the annulus and the pressureof the fluid flowing through the BHA. Sensors V1-V2 provide measurementsfor the fluid flow through the BHA and the wellbore. Additionally aspectrometric sensors S1 of the type described above may be placed in asuitable section 1050 of the BHA to measure the fluid and chemicalproperties of the wellbore fluid. Fiber optic sensor R1 is used todetect radiation. Acoustic sensors S1-S2 may be placed in the BHA fordetermining the acoustic properties of the formation. Additionallysensors, generally denoted herein as S may be used to providemeasurements for resistivity, electric field, magnetic field and othermeasurements that can be made by the fiber optic sensors. A light sourceLS and the data acquisition and processing unit DA are preferablydisposed in the BHA. The processing of the signals is preferably donedownhole, but may be done at the surface. Any suitable two waycommunication method may be used to communicate between the BHA and thesurface equipment, including optical fibers. The measurements made areutilized for determining formation parameters of the kind describedearlier, fluid properties and the condition of the various components ofthe drill string including the condition of the drill bit, mud motor,bearing assembly and any other component part of the drilling assembly.

[0091] While foregoing disclosure is directed to the preferredembodiments of the invention, various modifications will be apparent tothose skilled in the art. It is intended that all variations within thescope and spirit of the appended claims be embraced by the foregoingdisclosure.

What is claimed is:
 1. A system for monitoring a downhole productionfluid parameter, comprising: (a) an optical spectrometer in a wellbore,said optical spectrometer making measurements for the productionparameter in response to the supply of optical energy to thespectrometer; and (b) a source of optical energy providing the opticalenergy to the optical spectrometer.
 2. The tool of claim 1 wherein thespectrometer provides signals responsive to a downhole parameter whichis one of (a) presence of gas in a fluid, (b) presence of water in afluid, (c) amount of solids in fluid, (d) density of a fluid, (e)constituents of a downhole fluid, and (f) chemical composition of afluid.
 3. The system of claim 1 wherein the optical spectrometer ispermanently deployed in the wellbore.
 4. The system of claim 1 whereinthe source of optical energy is located in the wellbore.
 5. The systemof claim 1 wherein the optical spectrometer is located in a drill stringand makes the measurements during drilling of the wellbore.
 6. Thesystem of claim 1 further comprising a processor determining thedownhole parameter utilizing the measurements from the opticalspectrometer.
 7. The system of claim 6 wherein the processor processesdata at least in part downhole.
 8. A system for determining an acousticproperty of a subsurface formation, comprising: (a) an acoustic fiberoptic sensor in a wellbore providing measurements of an acousticproperty of the formation surrounding the wellbore; (b) a fiber optictemperature sensor in the wellbore for determining the temperature ofthe formation; and (c) a processor determining from the acoustic sensormeasurements the acoustic property of the formation that is compensatedfor temperature effects utilizing the temperature sensor measurements.9. The system of claim 8 wherein the acoustic property is one of (a)acoustic velocity of the formation, and (b) travel time of an acousticwavefront in the formation.
 10. The system of claim 8 wherein theprocessor processes the measurements at least in part downhole.
 11. Thesystem of claim 8 wherein the acoustic sensor is one of (a) permanentlyinstalled in the wellbore and (b) carried by a measurement-whiledrilling tool taking said measurements during drilling of the wellbore.12. A system for determining resistivity of a subsurface formation,comprising: (a) a fiber optic sensor in a wellbore providingmeasurements for resistivity of the formation surrounding the wellbore;and (b) a processor determining from the fiber optic sensor measurementsthe resistivity of the formation surrounding the wellbore.
 13. Thesystem of claim 12 wherein the fiber optic sensor is disposed in one of(a) on a measurement-while-drilling tool taking said measurements duringdrilling of the wellbore and (b) permanently installed in the wellbore.14. The system of claim 12 wherein the processor processes themeasurements at least in part downhole.
 15. A system for determining aformation parameter of a subsurface formation, comprising: (a) a fiberoptic sensor in a wellbore providing measurements for determining aparameter selected from a group consisting of electric field, radiationand magnetic field; and (b) a processor determining from the fiber opticsensor measurements the selected parameter.
 16. The system of claim 15wherein the fiber optic sensor is one of (a) permanently installed inthe wellbore and (b) carried by a measurement-while drilling tool takingsaid measurements during drilling of the wellbore.
 17. A downhole toolmonitoring system, comprising: (a) a tool in the wellbore; and (b) afiber optic sensor in a wellbore providing measurements for an operatingparameter of the tool.
 18. The system of claim 17 wherein the operatingparameter is one of (a) vibration, (b) noise (c) strain (d) stress (e)displacement (f) flow rate (g) mechanical integrity (h) corrosion (i)erosion (j) scale (k) paraffin (1) hydrate, (m) displacement, (n)temperature, (o) pressure, (p) acceleration, and (q) stress.
 19. Thesystem of claim 1 wherein the fiber optic sensor is one of (a) vibrationsensor (b) strain sensor (c) chemical sensor (e) optical spectrometersensor and (f) flow rate sensor, (g) temperature sensor, and (h)pressure sensor.
 20. The system of claim 17 wherein the downhole tool isone of a flow control device, packer, sliding sleeve, screen, mud motor,drill bit, bottom hole assembly, coiled tubing and casing.
 21. A methodof monitoring chemical injection into a surface treatment system of anoilfield well, comprising: (a) injecting one or more chemicals into thetreatment system for the treatment of fluids produced in the oilfieldwell; and (b) sensing at least one chemical property of the fluid in thetreatment system using at least one fiber optic chemical sensorassociated with the treatment system.
 22. The method of claim 21 whereinthe fiber optic chemical sensor is one of (a) a probe that includes asol gel and (b) an optical spectrometer that provides refracted lightindicative of the chemical property of the fluid.
 23. Ameasurement-while drilling (“MWD”) tool for use in drilling of awellbore, comprising: (a) at least one fiber optic sensor carried by thetool providing measurements responsive to one or more downholeparameters of interest during drilling of the wellbore; (b) a lightsource in the tool providing light energy to the at least one fiberoptic sensor for taking sid measurements; and (c) a processordetermining from said measurements the one or more parameters ofinterest at least in part downhole.
 24. The tool of claim 23 wherein theat least one fiber optic sensor includes at least one of (a) a fluidflow rate sensor, (b) a vibration sensor, (d) a spectrometer, (e) sensorthat determines a chemical property of the fluid, (f) a densitymeasuring sensor, (g) resistivity measuring sensor, (h) a plurality ofdistributed pressure sensors, (i) a temperature sensor, (j) a pressuresensor, (k) a strain gauge, (1) a hydrophone, (m) a plurality ofdistributed pressure sensors, (n) a plurality of distributed temperaturesensors, (o) an accelerometer, and (p) an acoustic sensor.
 25. The toolof claim 23 wherein the one or more parameters of interest include atleast one of (a) fluid flow rate, (b) flow of fluid through the tool,(c) vibration, (d) composition of wellbore fluid, (e) constituents offluid in the wellbore, (f) constituents of the formation fluid, (g)water content in the formation fluid, (h) presence of gas in theformation fluid (i) fluid density (j) a physical condition of the tool(k) a formation evaluation property, (1) resistivity, (m) temperaturegradient, and (n) pressure gradient.
 26. The tool of claim 23 whereinthe at least one fiber optic sensor includes a set of fiber opticsensors spaced along a fiber optic string.
 27. The tool of claim 26wherein at last some of the sensors are configured to providemeasurements for more than one downhole parameters.
 28. The tool ofclaim 23 wherein the at least one fiber optic sensor includes a set ofsensors and the processor multiplexes between such sensors according toprogrammed instructions provided to the processor to obtain measurementsof the desired parameters of interest.
 29. The tool of claim 23 furthercomprising a mud motor, said mud motor having a rotor rotating in anelastomeric stator upon the supply of a fluid under pressure to the mudmotor.
 30. The tool of claim 29 wherein the at least one fiber opticsensor includes a plurality of fiber optic temperature sensors in themud motor for measuring the temperature of the elastomeric stator,thereby providing an operating condition of the stator.
 31. The tool ofclaim 30 wherein the processor provides signals for adjusting supply ofthe fluid under pressure to the mud motor so as to maintain thetemperature of the stator at a desired value.
 32. A method of monitoringand controlling an injection operation, comprising: (a) locating in aproduction well a plurality of distributed fiber optic sensors; (b)injecting a fluid in an injection well formed spaced apart from theproduction wellbore; (b) determining from the fiber optic sensormeasurements a parameter of the formation between the production welland the injection well; and (c) controlling the injection of the fluidin response to the determined parameter.
 33. A downhole injectionevaluation system comprising: (a) at least one sensor permanentlydisposed in an injection well for sensing at least one parameterassociated with injecting of a fluid into a formation.
 34. A downholeinjection evaluation system as claimed in claim 33 wherein said systemfurther includes an electronic controller operably connected to said atleast one downhole sensor.
 35. A downhole injection evaluation system asclaimed in claim 34 wherein said at least one downhole sensor isoperably connected to at least one production well sensor to providesaid electronic controller, operably connected to said at least onedownhole sensor and to said at least one production well sensor, withinformation from both sides of a fluid front moving between saidinjection well and said production well.
 36. A system for optimizinghydrocarbon production comprising: (a) a production well; (b) aninjection well, said production well and said injection well being datatransmittably connected; and (c) at least one sensor located in eitherof said injection well and said production well, said at least onesensor being capable of sensing at least one parameter associated withan injection operation, said sensor being operably connected to acontroller for controlling injection in the injection well.
 37. A methodfor avoiding injection induced unintentional fracture growth comprising:(a) providing at least one acoustic sensor in an injection well; (b)monitoring said at least one sensor; and (c) varying pressure of a fluidbeing injected to avoid a predetermined threshold level of acousticactivity received by said at least one sensor.
 38. A method forenhancing hydrocarbon production wherein at least one injection well andan associated production well include at least one sensor and at leastone flow controller comprising providing a system capable of monitoringsaid at least one sensor in each of said wells and controlling said atleast one flow controller in each of said wells in response thereto tooptimize hydrocarbon production.
 39. A method of making measurements ina wellbore, comprising: (a) locating at least one fiber-optic sensor inthe wellbore, said sensor providing measurements responsive to one ormore downhole parameters; (b) locating a light source in the wellbore,said light source providing light energy to the at least one fiber opticsensor for making the measurements; and (c) processing the fiber opticsensor measurements and computing therefrom the one or more downholeparameters.
 40. The method according to claim 39, wherein the downholeparameters include at least one of (a) fluid flow rate, (b) flow offluid through the tool, (c) vibration, (d) composition of wellborefluid, (e) constituents of fluid in the wellbore, (f) constituents ofthe formation fluid, (g) water content in the formation fluid, (h)presence of gas in the formation fluid (i) fluid density (i) a physicalcondition of the tool (k) a formation evaluation property, (1)resistivity, (m) temperature gradient, (n) pressure gradient, and (o)seismic response of induced acoustic energy.
 41. A method of avoidingdrilling into preexisting wellbore, comprising: drilling a wellbore witha drilling assembly carrying a drill bit wherein the drill bit inducesacoustic energy into subsurface formations; providing at least one fiberoptic acoustic sensor in the preexisting wellbore for detecting acousticenergy generated by the drill bit; determining from the detected signalslocation of the drill bit relative to the preexisting wellbore; anddrilling the wellbore a desired distance from the preexisting wellborethereby avoiding drilling the wellbore into the preexisting wellbore.